Shallow subterranean hydrocarbon-bearing formations, which are typically at a depth of less than one thousand meters from the surface often contain heavy oil. The temperatures and hydrostatic pressures associated with these shallow formations are often less than 100° C. and 30 MPa, respectively. The United States Geological Survey (USGS) categorizes heavy oil based on the density and viscosity of the fluid. In particular, according to the USGS, medium heavy oil exhibits a density of 903 to 946 kg/m3 that corresponds with an API gravity of 25 to 18, and a viscosity from 10 to 100 mPa·s. Such medium heavy oil is typically mobile at reservoir conditions. Also, according to the USGS, extra heavy oil exhibits a density of 944 to 1021 kg/m3 that corresponds with an API gravity of 20 to 7, and a viscosity from 100 to 10,000 mPa·s. Such extra heavy oil is also typically mobile at reservoir conditions. The viscosity of heavy oil, such as those mentioned above, in combination with the permeability of the formation containing the heavy oil, determines the mobility of the heavy oil. In turn, the mobility of the heavy oil can impact significantly the techniques needed to sample and produce the heavy oil from the formation.
When sampling a heavy oil from a formation, it is desirable and often required that the sample is chemically representative (i.e., representative of the constituents and mole fractions) of the fluid in the formation from which the sample is extracted. Thus, the sample is preferably substantially free of contaminants such as drilling fluid or filtrate, and otherwise substantially chemically unaltered by the sampling process. A sample that represents accurately the characteristics of the fluid in the formation enables a suitable production strategy to be determined. However, sampling processes can, and often do, cause non-reversible, significant changes to the hydrocarbon fluid sampled from a formation, thereby significantly increasing the difficulty of selecting an appropriate production strategy.
In practice, techniques for sampling formation fluid must typically contend with constraints related to fluid mobility, formation type, undesirable phase transitions, the formation of emulsions or other mixtures with other phases (e.g., connate water), etc. In the case of sampling heavy oil, the above-mentioned constraints are sometimes compounded because heavy oil is often found in unconsolidated (e.g., sand) formations and the heavy oil is often not sufficiently mobile to permit sampling using a sampler having a probe assembly that contacts a borehole wall. More specifically, sampler pumps typically provide a minimum pump fluid-flow rate of about 0.1 cm3/s which, given the relatively low mobility of the heavy oil through the formation, can generate relatively large pressure drops that can result in the development of emulsions and/or collapse of the formation or a phase transition of the fluid.